1. Field of the Invention
This invention relates to producing wells having an artificial lift system for removing liquid from an underground formation. In one of its aspects, the invention relates to improved methods of and systems for control of artificial lift systems utilizing pressure measurements and pressure manipulation to detect the liquid level in the well bore to thereby increase the efficiency, operational predictability and to automate the artificial lift systems. In another of its aspects, the invention relates to the monitoring of production gas from a gas producing well and detection of the liquid level in the well bore to thereby control the artificial lift system to maximize gas production from the well while simultaneously maximizing artificial lift system performance and efficiency.
2. Description of Related Art
Artificial lift systems are commonly used to extract fluids, such as oil, water and natural gas, from underground geological formations. Oftentimes, the formations are more than 1,000 feet below the surface of the earth. The internal pressure of the geological formation is often insufficient to naturally raise commercial quantities of the liquid or gas from the formation through a bore hole. When the formation has a sufficient internal pressure to naturally lift the liquid from the formation, the natural pressure is often inadequate to produce the desired flow rate. Therefore, it is desirable to artificially lift the liquid from the formation by means of an artificial lift system.
Typically, the formation can comprise several separate layers containing the liquid and gas or can comprise a single large reservoir. A bore hole is drilled into the earth and passes through the different layers of the formation until the deepest layer is reached. Due to economic considerations, many bore holes extend only to the deepest part of the productive formation. In certain applications it is desired to extend the bore hole beyond the bottom of the productive formation. The portion of the bore hole that extends beyond the bottom of the formation and into the substrata is known as a xe2x80x9crat hole.xe2x80x9d The location and depth of the bore hole is carefully controlled because of the great expense in drilling the bore hole.
After the bore hole is drilled, the bore hole is usually lined with a casing along its entire length to prevent collapse of the bore hole, to control reservoir pressure and to protect surface water from contamination. However, the bore hole is often only lined with the casing to the top of the gas and liquid containing formation, leaving the lower section of the bore hole uncased. The uncased section is referred to as an open hole. The casing is cemented in place and sealed at surface by a wellhead and can have one or more pipes, tubes or strings (metal rods) disposed therein and extending into the bore hole from the wellhead. One of the tubes is typically a production tube, which is used to carry liquid to the surface.
Currently, many different types of artificial lift systems are used to lift the liquid from the formation. The most common artificial lift systems are: progressive cavity pumps, beam pumps and subsurface gas lift (SSGL). A progressive cavity pump is relatively expensive, approximately $20,000 to install, but can deliver relatively large volumes of liquid and remove all the liquid from the formation. A progressive cavity pump can comprise an engine or electric motor driven hydraulic pump connected to a hydraulic motor mounted on the top of the wellhead and connected to a pump at the bottom of a production tube. The hydraulic motor turns a rod string that is connected to a pump rotor, which turns with respect to a pump stator. Alternately, some progressive cavity pumps are driven by an electric motor attached to the top of the well head. The pump rotor is helical in shape and forms a series of progressive cavities as it turns to lift or pump the liquid from the bottom of the well bore into the production tube and to the surface. Although the progressive cavity pump is satisfactory in raising liquid from the formation, the hydraulic pump system requires a containment building and liner in the event of an oil leak. The possibility of an oil leak in the progressive cavity pump system also raises environmental concerns because many of the bore holes are drilled in environmentally sensitive or wilderness areas. The progressive cavity pump also requires, in certain applications, at least 100 feet of a rat hole, which adds extra cost. Of the previously mentioned artificial lift systems, the progressive cavity pump has the highest maintenance costs and greatest amount of down time requiring rig service. This down time often results from a lack of good liquid level control which allows the well to be pumped off causing damage to the pump system. Also, a soft seal stuffing box which must be lubricated regularly is used to seal around the rotating rod string and acoustic annular liquid levels must be obtained at regular intervals to ensure that the liquid is adequately high above the pump so that it does not run dry and destroy itself.
A beam pump is also relatively expensive, approximately $18,000, to install but can also remove all the liquid from the formation. The beam pump comprises a pivotally mounted beam that is positioned over the wellhead and connected to a rod string extending into the production tube within the casing in the bore hole. The lower end of the rod string is connected to a pump disposed near the bottom of the well bore. The beam pump can be operated by a gas engine or an electric motor. The beam pump has several disadvantages. First, there are many environmental concerns. There may be leakage in the engine or gear box of the power source, requiring construction of a containment area. Further, if an electric motor is used in place of the gas engine, it is necessary to run a power line to the electric motor, which often destroys or degrades the surrounding environment. The beam pump, like the progressive cavity pump, has many moving components that require regular lubrication. The beam pump also uses a soft seal stuffing box to seal around the reciprocating rod string to contain liquids and gases produced up the production tube.
The SSGL is the least expensive artificial lift system to install, approximately $7,500. The SSGL uses pressurized gas carried by a separate tube, commonly referred to as a side string, from the surface to the lower end of the production tube to eject the liquid in the production tube to the surface upon injection of a blast of pressurized gas. The production tube usually has at its lower end a one-way valve called a xe2x80x9cstanding valvexe2x80x9d which permits liquid standing in the formation to enter the production tube and rise in the production tube to the level of liquid in the formation. Often the SSGL system will have a plunger disposed within the production tube, but a plunger is an optional device to provide mechanical advantage for the blast of injection gas.
The SSGL is the most environmentally friendly, maintenance free and energy efficient of the three commonly used artificial lift systems. Unlike the other artificial lift systems, the subsurface gas lift system requires no systematic lubrication of the gas regulator and the motor valve. The SSGL maintains greater integrity of the well head in controlling the possibility of liquid leaks because the well head components are hard piped with no friction oriented soft seal such as is found in the stuffing boxes of the progressive cavity and beam pumps. The SSGL is virtually silent during operation and has very little surface equipment compared to a beam pump or progressive cavity pump. Therefore, it has less audible and visual impact on the surrounding environment.
The greatest disadvantage of the SSGL is that it becomes less efficient and more difficult to control as more and more liquid is removed from the formation. The SSGL can only raise the column of liquid in the production tube. The column of liquid in the production tube is equal to the level of liquid in the annulus and therefore the level of liquid in the formation if the production tube and annulus are equalized into a common line at surface. As more and more liquid is removed from the formation, the level of liquid in the formation decreases. Therefore, as the level of liquid in the production tube decreases and a continuously smaller and smaller amount of liquid is raised for substantially the same amount of energy. As the liquid level in the subsurface gas lift system decreases or the influx of liquid to the well bore becomes erratic, there becomes a point where it is no longer operationally predictable, safe or productive to use the subsurface gas lift system. Oftentimes, the subsurface gas lift system is operated as a crippled and inefficient system without a plunger or replaced with a beam pump and its accompanying undesirable attributes. Optionally, a xe2x80x9crat holexe2x80x9d can be bored with the bore hole in a subsurface gas lift system so that most of the liquid can be raised from the formation by placing the gas injection point below the level of the formation and in the rat hole. However, many bore holes were drilled without a rat hole before artificial lift became a generally accepted method of production and the cost associated with boring a rat hole is such that most companies still prefer to drill little, if any, rat hole.
Another disadvantage that is common to all artificial lift systems is that as the liquid level decreases or the influx of liquid to the well bore becomes erratic, the systems become operationally more difficult to efficiently control without damaging themselves regardless of the depth of the rat hole. In the event of no liquid level, the progressive cavity pump will quickly torque up and destroy the down hole pump, twist off the rod string or destroy the stator assembly. The beam pump will begin to pound as gas is drawn into the pump, the end result of which will be a scored or damaged pump barrel and eventually a parted rod string. The SSGL may xe2x80x9cdry cycle,xe2x80x9d a condition where the plunger arrives at the surface and bottom of the well with no liquid cushion and, therefore, possibly at a damaging velocity. As the level of liquid decreases in an SSGL system, there is an increased need to use the mechanical advantage provided by a plunger to optimize the use of injection gas. The installation of a plunger into a well bore that has a continually declining or erratic liquid level requires constant vigilance on the part of the system operator to reduce the volume of gas injected into the production tube to keep the plunger from developing higher and higher velocity as the liquid level decreases. If the SSGL injection is left without adjustment the plunger velocity often increases to a point where the lubricator and the standing valve will be damaged by plunger impact.
In summary, the damage to the progressive cavity and the beam pumps will require a work-over rig for repairs. The damage to the SSGL seldom requires more than a small wire line truck for a few hours to retrieve and repair the damaged components. However, each of these systems, if controlled improperly, can have catastrophic failures that can be physically dangerous to the operator, costly to repair and can inflict environmental damage.
Most production companies have a mix of all the lift system types throughout their fields and while SSGL is the most environmentally friendly and energy efficient, there are fields in which the beam pump and progressive cavity pump systems are used exclusively. For various reasons that include high rates of liquid production, easy access to electricity, lack of a pipeline distribution system to supply high pressure gas for a SSGL system, lack of compressor capacity to support SSGL systems or engineering preference, many wells use beam pumps, progressive cavity pumps and in some circumstances submersible electric pumps. All of these pumps will suffer damage if the liquid level in the well declines to a point where gas enters the pump or the well enters a pumped off condition.
There are various methods that can be used in conjunction with these pump systems to control pump off. In the case of a beam pump or progressive cavity pump, there are flow monitoring devices that can be installed in the liquid ejection line at surface to monitor the liquid flow to make sure it does not contain excessive quantities of gas or does not stop flowing. If an excessive quantity of gas or a no flow condition is detected, the pump will be shut down. In this method, a pump that is driven by an electric motor may be automatically shut down for a period of time and then restarted to pump until the well is pumped off again. A pump that is driven by a gas engine will be shut down and must be restarted by an operator. This method of pump off detection is inherently weak in that pump off is only detected after-the-fact. The influx of gas into the production tube can cause gas locking of the pump, excessive wear due to lack of liquids or excessive corrosion due to free gas in the production tube. Further, there is no provision for constant monitoring of the liquid level in the well bore to make sure the liquid has been reduced to a level below the productive formation. Therefore, acoustic annular liquid levels must be taken at regular intervals to optimize the performance and efficiency of the artificial lift system.
Another method of monitoring pump off in a system using an electricity driven submersible or progressive cavity pump is to monitor the current draw caused by the pump motor. In the case of the progressive cavity pump, if gas is being drawn into the pump, the current draw may increase because of increased friction, due to the lack of lubrication and cooling provided by the production liquids, which in turn causes the electric motor to work harder. In this method, the pump can be shut down for a period of time to allow liquid to enter the well bore before starting the pump again. However, this method of detection is also an after-the-fact detection of pump off and does not compensate for variations of liquid volume entering the well bore. In the case of the submersible electric pump the current draw may decrease as gas enters the pump due to the impellers spinning in a gaseous fluid. In this case, the system would be shut down to keep the pump from overheating due to lack of cooling liquids. Again, detection is after-the-fact and damage may be done to the pump.
In another prior art control system for the electric progressive cavity pump and the submersible electric pump system, the current load is monitored and this value is used to automatically adjust a variable speed drive on the electric motor. This control method resembles the use of a rheostat where power to the system is controlled to allow for speed adjustment of the electric motor and therefore speed adjustment of the pump. In this method, the motor speed is adjusted based on current load to control system pump off. However, adjustments are made in response to after-the-fact detection of pump off and the system is still unable to detect precise liquid levels in the well bore.
With the submersible electric pump, the progressive cavity pump and beam pump system, another inefficiency can develop if the well bore is configured with a deep rat hole. If the pump is placed substantially below the productive formation and into the rat hole and the liquid in the annulus is reduced down to the level of the pump, it will require significantly more energy to lift the liquid from the well bore than would be required if the liquid level in the annulus was up to the bottom of the productive formation or at the top of the rat hole. For example, if a well is 1000 feet deep to the base of the productive formation and has a 200 feet deep rat hole for a total well depth of 1200 feet, and the liquid being pumped has the density of fresh water with a pressure gradient of 0.433 psi per vertical foot, the head pressure of a liquid column inside the production tube at a depth of 1000 feet will be 433 psi and at a depth of 1200 feet the liquid head pressure will be 519.6 psi. In this scenario if a pump is set to a depth of 1200 feet (200xe2x80x2 into the rat hole below the productive formation) and the liquid level in the annulus is lowered to the level of the pump, the pump must overcome 1200 feet of hydrostatic head pressure or 519.6 psi to lift the liquid to the surface of the ground. Alternately, if the pump is set to a depth of 1200 feet but the liquid level in the annulus is maintained up to the bottom of the productive formation (200 feet above the pump in the annulus) the pump will only need to overcome 433 psi of hydrostatic head pressure to lift the liquid to the surface due to the equalizing force of the liquid in the annulus. In the scenario where the liquid level is reduced unnecessarily low in the annulus it will require approximately 20% more energy to lift a given volume of liquid to the surface than if the liquid level was maintained up to the bottom of the productive formation due to the lack of the balancing effect of the liquid in the annulus.
Therefore, there is a need to provide a method and system to conserve energy and increase longevity of the well bore equipment by precise control of the liquid level within the well bore to avoid pump off in artificial lift systems. A systemic method of control of the liquid level will improve the efficiency of the pump while further reducing the manpower requirements to operate the system by reducing the need for operator intervention with the artificial lift system to control liquid level to optimize well production and to prevent the system from damaging itself. There is further a need to have cost effective oil or gas well artificial lift systems that are relatively environmentally and operationally safe, low maintenance, operationally predictable, easy to use, have an acceptable level of efficiency and have the ability to automatically compensate to meet the variable conditions of a dynamic well bore.
The invention relates to a method and system of producing gas and liquid from a gas and liquid-containing underground stratum comprising a well bore extending between the surface of the ground to the stratum, the well bore having a casing and a production tube defining an annulus through which gas from the stratum passes and is collected at the surface of the ground through a production line. The production tube extends from the surface of the ground and is in fluid communication with the gas and liquid-containing stratum through which the liquid is collected from the well and removed to the surface by artificially raising the liquid in the production tube to the surface to thereby release gas from the formation to the well bore and production line. A side string tube extends from the surface of the ground through the annulus and is in fluid communication with the gas and liquid-containing stratum. An artificial lift system is provided for artificially raising the liquid in the production tube to the surface to thereby release gas from the formation to the well bore and production line.
According to the invention, the level of liquid in the well bore is reiteratively measured by reiteratively detecting at least the pressure in the side string tube, comparing the measured level of liquid with a predetermined value representative of a desired level of liquid in the well bore and controlling the artificial raising of the liquid in the production tube in accordance with the measured level and predetermined value so that the measured level reaches the predetermined value.
In one embodiment of the invention, the artificial raising of the liquid in the production tube is accomplished by injecting a volume of gas into a bottom portion of the production tube through the side string tube when the measured level of liquid (as detected by pressure) reaches the predetermined value.
According to a further aspect of the invention, a relatively small amount of gas is injected into the side string tube to clear any liquid that may be present in the side string tube, just prior to or during the detection of the pressure in the side string tube.
According to an even further aspect of the invention, the pressure in the production tube is detected, and the differential pressure between the detected side string pressure and the production tube pressure is calculated and compared to the predetermined value.
According to a further aspect of the invention, the rate of gas production in the production line is monitored and the predetermined value representative of the desired level of liquid in the well bore is adjusted to maximize gas production and liquid level. Preferably, the adjustment of the predetermined value is performed over a plurality of gas lift injection cycles or otherwise over a period of time for artificial lift systems incorporating a pump.
Still further according to the invention in a SSGL system, the time required to artificially raise the liquid in the production tube to the surface of the ground is measured and compared with a predetermined and desired time of liquid rise. The volume of gas injected into the production tube during the injection step is adjusted until the measured time of liquid rise to surface is substantially equal to the predetermined and desired time of liquid rise to surface.
According to another aspect of the invention, a pump is operatively associated with the production tube for artificially raising the liquid in the production tube. Depending on the well conditions, the pump can be started, stopped, sped up or slowed down to control the level of liquid in the well bore.
According to an even further aspect of the invention, the time is monitored at which the level of liquid in the well bore is measured and the predetermined set point representative of desired liquid level is altered when the time substantially equals a first predetermined time, such as the time just before a peak power draw from a power company, to thereby artificially raise the liquid in the production tube when the level of liquid in the well bore is different from the desired level. Preferably, the predetermined set point is lowered to a lower set point to thereby lower the level of liquid in the well bore to a reduced level, such that artificially raising the liquid in the production tube can be omitted during peak hours without interference with well production.
In a system for producing gas according to the invention, a first pressure sensor detects the pressure in the side string tube at surface and generates a first pressure signal representative of the detected pressure in the side string tube. A controller is operably connected to the first pressure sensor for reiteratively computing the level of liquid in the production tube or well bore in response at least in part to the first pressure signal. The computed level of liquid in the production tube or well bore is compared to a predetermined value representative of the desired level of liquid in the well bore and the artificial lift system is controlled to allow the level of liquid in the well bore to reach the desired level of liquid in the well bore.
In the embodiment of the invention wherein the artificial lift system comprises a gas injection system with an injection valve for periodically injecting a blast of gas into a lower portion of the production tube through the side string tube, the controller is operably connected to the injection valve and is adapted to control the initiation of the blast of gas into the production tube to artificially lift the liquid in the production tube to the surface of the ground. The controller actuates the injection valve to initiate the injection of gas into the side string tube when the measured level of liquid in the production tube reaches a predetermined value representative of the desired level of liquid in the production tube and well bore. Preferably, the controller is adapted to compute the level of liquid in the production tube in response to the first pressure signal after liquid has been substantially cleared from the side string tube by the injection of a minuscule volume of gas.
In a preferred embodiment of the invention wherein the artificial lift system comprises a gas injection system, a second pressure sensor is fluidly attached to the production tube to sense the pressure therein and to generate a second pressure signal representative of the pressure in the production tube. A controller is operably coupled to the second pressure sensor and is adapted to compute the level of liquid in the production tube in response at least in part to the first and second pressure signals. In a preferred embodiment of the invention, the controller is adapted to compute the level of liquid in the production tube in response to the difference between the first and second pressure signals.
In another embodiment of the invention, the artificial lift system comprises a beam pump. In still another embodiment of the invention, the artificial gas lift system comprises a progressive cavity pump. In still another embodiment of the invention, the artificial lift system is an electrically driven submersible pump.
In a preferred embodiment of the invention wherein the artificial lift system incorporates a pump, a second pressure sensor is fluidly attached to the annulus to sense the pressure therein and to generate a second pressure signal representative of the pressure in the annulus. A controller is operably coupled to the second pressure sensor and is adapted to compute the level of liquid in the well bore in response at least in part to the first and second pressure signals.
According to one aspect of the invention, the controller is adapted to compute the level of liquid in the well bore in response to the difference between the first and second pressure signals. Preferably the controller is adapted to generate an output signal for controlling the initiation of the artificial lift system when the liquid level in the well bore as detected by pressure reaches a predetermined value.
According to another embodiment of the invention in an SSGL artificial lift system, an arrival detector is mounted at an upper portion of the production tube or on the lubricator to detect the arrival of the ejected liquid or plunger from the lower portion of the production tube and to generate an arrival signal representative thereof. The controller is operably coupled to the arrival detector and is adapted to compute the time required to artificially lift the liquid or plunger from the lower portion of the production tube to the arrival detector, to compare the computed trip time of the liquid or plunger to a predetermined and desired trip time, and to control the operation of the injection valve to adjust the volume of gas injected into the side string tube during subsequent injection cycles until the computed trip time of the lifted liquid or plunger substantially equals the predetermined and desired trip time.
In yet another embodiment of the invention, a production detector in the production line measures the rate of gas production and generates a production signal responsive thereto. The controller is further operably coupled to the production detector and is adapted to compute the rate of gas production responsive to the production signal and to adjust the predetermined value representative of the desired liquid level in the production tube or well bore to maximize the gas production in the production line.
The invention can be applied to a single producing well with the controller physically at the wellhead. Alternatively, a controller can be used to control a plurality of wells. The controller can be located geographically remote from each of the wells and in communication with the sensors and control valves at the well head through electrical communication lines or through telemetry.
The invention contemplates several different, but related, methods of pressure monitoring for control of the gas injection cycle in a well using a subsurface gas lift artificial lift system, each with the objective of detecting the level of liquid in the production tube and therefore the well bore to initiate the gas injection cycle. These methods have varying accuracy according to the operational need dictated by the well bore configuration. In one embodiment of the invention, operational efficiency and control is enhanced by volumetric measurement of production gas to control the injection cycling of gas into the well by automated control of the liquid level in the well bore. In still another embodiment of the invention, injection volumes are regulated based on liquid or plunger travel time to surface or calculated average liquid or plunger time. It is to be understood, however, that each of the embodiments can be used by itself or combined with one another to achieve the desired system efficiency or control of a subsurface gas lift system.
The invention also contemplates several variations of pressure monitoring for control of the artificial lift systems in wells using the beam pump, progressive cavity pump or the electric submersible pump methods of artificial lift, each with the objective of detecting the level of liquid in the well bore prior to making adjustments to the artificial lift system. These methods have varying accuracy according to the operational need dictated by the well bore configuration. In one embodiment of the invention, operational efficiency and control is enhanced by volumetric measurement of production gas to control the operation of the artificial lift system by automated control of the liquid level in the well bore.
Fundamental to an understanding of how the pressure monitoring and control system of the invention can have a positive impact on artificial lift system performance is an understanding of the variations in pressures that can and do exist at various points in the artificial lift system. These pressures, measured at the appropriate time and interpreted correctly, will give a very accurate determination of the liquid level in the production tube and/or well bore.
Pressures in a bore hole are commonly referred to in the terms of pressure gradients. xe2x80x9cGradientxe2x80x9d is defined as psi per vertical foot in the bore hole. Fresh water will have a gradient of 0.433 psi per vertical foot, whereas low pressure gas gradient may be as minimal as 0.002 psi per vertical foot. In effect, a 1000xe2x80x2 column of fresh water will have a bottom hole or head pressure of 433 psi whereas the low pressure gas will have a bottom hole or head pressure of 2 psi.
In a well using the subsurface gas lift (SSGL) method of artificial lift, subsequent to the injection portion of the SSGL cycle, liquid will enter the bottom of the production tube through the standing valve attached to the injection mandrel and displace the gas in the production tube into the ejection line and to the collector at surface until the well bore has achieved static equilibrium. (Static equilibrium is commonly defined as the time when head pressure at the injection mandrel is substantially equalized between the inside of the production tube and the annular section of the well bore. Therefore, a no-flow condition exists between production tube and the annulus.) The column of liquid entering the production tube and displacing the gas into the flow line at surface will at the same time try to enter into the side string tube attached to the injection mandrel above the standing valve. However, the side string tube, unlike the production tube, is closed at surface. Therefore, the liquid can only enter the side string tube until the cumulative head pressure of the gas and liquid in the side string tube at the injection mandrel is equal to the cumulative head pressure of the gas and liquid in the production tube at the injection mandrel. At this point, the difference between the side string injection line pressure at surface and the production tube pressure at surface multiplied by the appropriate liquid gradient pressure factor will give the approximate liquid level in the production tube. The reason the liquid level is only approximate is due to the fact that liquid has entered the side string tube to compress the gas in the side string tube which causes there to be two different gradients in the side string tube, one for gas and one for liquid, the level of which is unknown. At this point, pressure manipulation will accurately determine actual liquid level in the production tube. Manipulation is accomplished by the injection of a minuscule volume of gas into the side string injection line attached to the side string tube. This volume will displace the liquid in the side string tube, causing only gas to be present in the side string tube. This volume is estimated based on the diameter of the side string tube and the estimated height of liquid in the side string tube. Typically, the amount of gas is determined by monitoring the pressure in the side string injection line at surface as the gas is injected into the side string tube and the volume is typically very small as compared to the amount of gas injected during the SSGL injection cycle. The pressure in the side string injection line will increase as the minuscule volume of gas is injected into the side string tube until all of the liquid in the side string tube is forced into the production tube at which time the pressure will stabilize. This step can be carried out manually by an operator or automatically by a controller. As a practical matter, the minuscule volume of gas can be injected continuously between injection cycles to maintain the side string tube free of liquid. As a result, the difference between the pressures in the side string injection line at surface and the production tube at surface multiplied by the appropriate liquid gradient factor is used to compute the level of liquid in the production tube with great accuracy. The computations are done reiteratively until the computed level of liquid in the production tube is equal to a predetermined level which is based on the well bore characteristics. When the predetermined level and the computed levels are equal, the SSGL injection cycle can then be initiated by the controller if desirable. This known level of liquid in the production tube can thus be used to greatly improve the efficiency of the SSGL system by effecting the cycling only when an optimum liquid level has been achieved while eliminating the single greatest control problem for SSGL, the xe2x80x9cdestructive dry cyclexe2x80x9d that often causes mechanical damage and can cause environmental damage.
The pressure monitoring and calculation and control steps are preferably carried out for a first time period to determine the level of liquid in the
In a more sophisticated embodiment of the invention, a minuscule volume of gas is injected into the side string injection line sufficient to displace the influx of liquid in the side string tube into the production tube, the side string pressure is monitored throughout the SSGL non-injection or off cycle as a measure of the level of liquid in the production tube and the measured pressure is compared with a predetermined value representative of the desired level of liquid in the production tube. The injection of a minuscule volume of gas in the side string tube eliminates the unknown side string tube liquid level so that the controller can more accurately detect the level of liquid in the production tube. The SSGL gas injection cycle is initiated when the detected pressure substantially equals the predetermined pressure representative of a desired liquid level in the production tube and therefore the well bore. While this method will more accurately reveal the level of liquid in the production tube to the controller, the system timing will still have an arbitrary pressure initiation base that will be dependent on the operator estimating an average production tube pressure at surface. Therefore, this method will perform best on wells with substantial rat hole or with relatively high liquid levels in which the side string injection line pressure will become noticeably elevated due to the production tube liquid gradient.
In a third embodiment of the invention, the side string injection line pressure and the production tube pressure at surface is monitored and detected throughout the SSGL non-injection or off cycle and a differential pressure representative of the level of liquid in the production tube is computed based on the detected pressures; the computed differential pressure is compared to a predetermined value representative of the desired level of liquid in the production tube; and the SSGL gas injection cycle is initiated when the computed pressure is substantially equal to the predetermined value. Thus, the SSGL gas injection cycle is controlled to permit the level of liquid in the production tube to rise to a with a predetermined value representative of the desired level of liquid in the production tube. The injection of a minuscule volume of gas in the side string tube eliminates the unknown side string tube liquid level so that the controller can more accurately detect the level of liquid in the production tube. The SSGL gas injection cycle is initiated when the detected pressure substantially equals the predetermined pressure representative of a desired liquid level in the production tube and therefore the well bore. While this method will more accurately reveal the level of liquid in the production tube to the controller, the system timing will still have an arbitrary pressure initiation base that will be dependent on the operator estimating an average production tube pressure at surface. Therefore, this method will perform best on wells with substantial rat hole or with relatively high liquid levels in which the side string injection line pressure will become noticeably elevated due to the production tube liquid gradient.
In a third embodiment of the invention, the side string injection line pressure and the production tube pressure at surface is monitored and detected throughout the SSGL non-injection or off cycle and a differential pressure representative of the level of liquid in the production tube is computed based on the detected pressures; the computed differential pressure is compared to a predetermined value representative of the desired level of liquid in the production tube; and the SSGL gas injection cycle is initiated when the computed pressure is substantially equal to the predetermined value. Thus, the SSGL gas injection cycle is controlled to permit the level of liquid in the production tube to rise to a predetermined level before initiation of the gas injection cycle. This method makes the system dynamic in that variations in production tube pressure at surface will have no effect on the differential pressure between the side string injection tube at surface and the production tube at surface. This differential pressure multiplied by the appropriate gradient factor for the liquid in the production tube will compute a relatively accurate estimation of the liquid level in the production tube regardless of fluctuations in the production tube surface pressure caused by changes in the pressure on the flow line. The pressures in this method still represent an estimate of the liquid level in the production tube due to the fact that there will be some influx of liquid into the side string tube. Therefore, while this method will more accurately detect the liquid level than the first two embodiments, it will still perform best on wells with at least some rat hole or with higher than average liquid levels where side string pressures will become marginally elevated due to production tube liquid gradient.
In a fourth embodiment of the invention, the same steps as the third embodiment are followed with the addition of the step of injecting a minuscule or relatively small volume of gas into the side string injection tube sufficient to displace the influx of liquid in the side string tube into the production tube while determining a differential pressure representative of the level of liquid in the production tube. In this method, any error resulting from the unknown side string tube liquid level is eliminated. The liquid level is thus more accurately determined for initiating the SSGL gas injection cycle. In this method, the system is dynamic in that variations in the production tube pressure at surface will have no impact on the differential pressure between the production tube and the side string pressures. Furthermore, because the side string tube will have only a gas gradient within it, the differential pressure multiplied by the appropriate liquid gradient factor will determine an exact liquid level in the production tube. In this method, the operator will be able to choose very accurately, by virtue of pressure, the liquid level that he or she desires to carry in the well bore and production tube to best optimize the available rat hole, conserve on injection volumes, increase well production and control the SSGL system.
In yet another embodiment of the invention, any of the foregoing methods are followed and gas production is measured relative to the liquid level in the well bore, and the liquid level within the well bore is automatically adjusted to maximize well production while simultaneously optimizing liquid level in the production tube to maximize the quantity of liquid delivered in each injection cycle. In many well bores, the lower section of the xe2x80x9cproductivexe2x80x9d formation above the rat hole does not actually contribute to production. Reduction of the liquid level below the point in the formation that is not contributing production causes the level of liquid in the production tube to decrease. This unnecessary reduction in liquid level causes inefficiency in the SSGL system by increasing the need for SSGL cycles, thus using more injection gas to deliver a given quantity of liquid. In this new interactive and dynamic method of control, production gas is measured at the well head to establish the current production volumes. The controller is programmed with conventional software to use time weighted production volume averages to determine the current well bore production based on actual measurements. The predetermined liquid level pressure (PSI) or differential pressure (DP) set point for the initiation of the SSGL injection cycle is automatically adjusted upward so that the liquid level in the well bore rises before initiating the SSGL injection cycle as determined by any of the previous liquid level determination methods. As the liquid level rises, there will come a time when the gas production will decline within the specified time weighted average. At that point, the predetermined liquid level set point will be automatically reduced to decrease the level of liquid within the well bore before initiation of the SSGL cycle. The well bore response in the form of increased volumetric production is then monitored. As the production increases within the specified time and volume parameters, the predetermined set point for the desired liquid level will continue to be reduced until no more increase in production volume is detected within the specified time parameters. At that time, the set point will remain unchanged for a specified time period. At the end of the specified nonmanagement period, the liquid level management procedure described above will be repeated until the next dormant period. It is to be understood that the automated liquid level management method will be done with adjustments taking place over the course of many hours and possibly days, the end result being the maximum liquid level sustainable within a given well bore with minimal interference with production and a reduced need of injection gas.
In another embodiment of the invention, the plunger travel time to surface is monitored beginning at the start of the SSGL injection period and the plunger trip time-within the production tube is computed. Plunger efficiency to remove the greatest quantity of the liquid that has entered the production tube is based on a liquid seal between the plunger O.D. and the production tube I.D. This liquid seal is created by turbulent flow around the plunger. Therefore, the seal is dependent upon the velocity of the plunger. If the plunger travels either too slow or too fast, liquid will escape past the plunger and not be ejected from the production tube, causing a waste of compression energy and the need for more cycles to eject the liquid. Furthermore, current operational technique has proven that it is more predictable to control a short, relatively high pressure, high volumetric rate, blast of injection gas into the production tube and provide a restricted orifice at the surface for the liquid to pass through to abruptly slow a high speed plunger rather than to use a relatively long injection period of lower pressures and lower volumetric rates. This restricted orifice at the surface creates another inefficiency in the SSGL system in that as the liquid arrives, it causes the production tube pressure at the surface to rise dramatically which, in turn, causes the need for more injection gas volume and a vicious cycle of inefficiency ensues. Field testing has revealed that in SSGL systems the average plunger velocity in the production tube is 1.8 times the optimum published speed and 1.25 times that of the maximum efficient velocity published in industry standard journals. Another issue to consider is that this average velocity does not reveal what the initial velocity off bottom must be to allow the injection gas to be shut off 20 to 30 seconds into a one-minute plunger trip to the surface. In this new and unique method, a predetermined optimum plunger trip time window is computed based on production tubing depth, well bore pressures and other pertinent factors known to those workers in this field. The actual plunger trip time is measured and compared to the predetermined optimum plunger trip time window at the end of each injection cycle. If the plunger trip time to surface is too long or the plunger does not arrive, the SSGL injection period is lengthened to increase average plunger velocity to thereby decrease plunger trip time and to encourage plunger arrival at surface. If the plunger trip time to surface is too short a period, the injection period will be decreased to reduce average plunger velocity to thereby increase plunger trip time and to control plunger impact into the lubricator at surface. With this method, it is possible to better manage the quantity of injection gas used per cycle, reduce the rate at which the gas is injected, reduce pressure needed on the high pressure injection line going to the well, increase the size of the restrictive orifice at surface to reduce production tube pressures and better control the average velocity of the plunger throughout the length of the production tube.
In some bore holes, a plunger is not installed in the production tube in a well in which an SSGL artificial lift system is used. In these systems, the arrival time of the liquid column at the surface is monitored and used to compute the trip time of the liquid column during the injection of the gas during the SSGL cycle. The trip time of the liquid column is compared to a predetermined and desired trip time and the SSGL injection period is adjusted to maintain the average velocity of the liquid column during the SSGL injection cycle within a predetermined range.
In wells using the beam pump, progressive cavity pump or electric submersible pump methods of artificial lift the pressure monitoring and liquid detection methods of the invention can be used to substantially improve the operational control and efficiency of these systems. In these types of artificial lift systems the side string tube is not fluidly connected with the I.D. of the production tube as in the SSGL system but rather is fluidly connected with and terminated in the annulus. The side string termination point in the annulus may vary according to the desired accuracy of liquid level detection, well bore characteristics or engineering preference as long as the termination point is as deep in the well bore as the lowest desired liquid level. Also, in artificial lift systems incorporating a pump, when a second pressure transmitter is used to detect the pressure at surface, this second pressure transmitter is fluidly attached to detect the annulus pressure rather than being attached to detect the liquid ejection line and production tube pressure as in an SSGL system because in the pump system the liquid level in the annulus is being specifically measured rather than the liquid level in the production tube. While there are subtle differences between how the invention is applied to artificial lift systems incorporating a pump as compared to artificial lift systems using sub surface gas lift, all of the previously mentioned well bore pressure gradient information is applicable and will be used herein as the basis for the following descriptions of the embodiments of the invention as applied to artificial lift systems incorporating a pump.
The pressure monitoring and calculation steps are preferably carried out for a first time period to determine the level of liquid in the well bore and the artificial lifting step is carried out during and/or subsequent to the first time period. Preferably, the control of the artificial lifting step is carried out at the completion of the first time period. Preferably, the control of the artificial lifting step comprises the altering of the pump operation to lift the liquid in the production tube to the surface of the ground. Preferably the altering of pump operation can include turning the pump system on or off, or increasing or decreasing the speed of the artificial lift pump to increase or decrease the volume of liquid being lifted from the well bore into the production tube and to the surface of the ground to thereby control the liquid level in the well bore at a predetermined and desired liquid level as detected by pressure.
In the first and most primitive embodiment of the invention the side string pressure is continuously detected to determine the level of liquid in the well bore. The detected pressure is compared with a predetermined pressure representative of the desired level of liquid in the well bore and the pump operation is altered to maintain the detected pressure representative of liquid level substantially equal to the predetermined pressure to thereby maintain the desired liquid level in the well bore. In this case, the computation of the liquid level in the well bore will simply be the use of the detected pressure in the side string tube. This method will require the placement of the termination point of the side string tube in the annulus to be very close to the desired liquid level and will require the greatest amount of operator intervention to work with nominal efficiency. This method will only give a rough estimate of the liquid level in the well bore due to the fact that there will be an influx of liquid into the side string tube and the annulus pressure at surface will only be an estimated average due to fluctuations in flow line pressure. Further, this method is inherently weak because there is not a source of injection gas at surface it will be necessary for the liquid level in the well bore to fall below the termination point of the side string tube occasionally to allow the side string tube to be cleared of all liquids because the smallest release of pressure at surface will cause the side string tube pressure at surface to decline, falsely indicating a low liquid level in the well bore.
In a second and more sophisticated embodiment of the invention, a minuscule volume of gas is injected into the side string injection line sufficient to displace the influx of liquid in the side string tube into the annulus, the side string pressure is monitored as a measure of the level of liquid in the well bore and the measured pressure is compared with a predetermined pressure representative of the desired level of liquid in the well bore. The injection of a minuscule amount of gas in the side string tube eliminates the unknown side string tube liquid level so that the controller can more accurately detect the level of liquid in the well bore. The pump operation is altered when the detected pressure substantially equals the predetermined pressure representative of a desired liquid level in the well bore. Further, in this embodiment, if the side string tube is terminated substantially below the highest desired liquid level it is possible to allow the pump operations to be altered with a substantial variation of liquid level in the well bore as detected by pressure. While this method will more accurately reveal the level of liquid in the well bore to the controller, the system control will still have an arbitrary pressure initiation base that will be dependent on the operator estimating an average annulus and production line pressure at surface. Therefore, this method will perform best on wells with substantial rat hole or with relatively high liquid levels in which the side string injection tube pressure will become noticeably elevated due to the well bore liquid gradient.
In a third embodiment of the invention, the side string injection tube pressure and the annulus pressure at surface are monitored and detected continuously and a differential pressure representative of the level of liquid in the well bore is computed based on the detected pressures; the computed differential pressure is compared to a predetermined value representative of the desired level of liquid in the well bore; and pump operations are altered when the computed pressure is substantially equal to the predetermined value. Thus, the artificial lifting is controlled to permit the level of liquid in the well bore to rise to a predetermined level before lifting the liquid to the surface of the ground. This method makes the system dynamic in that variations in annulus or flow line pressure at surface will have no effect on the differential pressure between the side string injection tube at surface and the annulus pressure at surface. This differential pressure multiplied by the appropriate gradient factor for the liquid in the well bore will compute a relatively accurate estimation of the liquid level in the well bore regardless of fluctuations in the annulus surface pressure caused by changes in the pressure on the flow line. The pressures in this method still represent an estimate of the liquid level in the well bore due to the fact that there will be some influx of liquid into the side string tube. Therefore, while this method will more accurately detect the liquid level than the first two embodiments, it will still perform best on wells with at least some rat hole or with higher than average liquid levels where side string pressures will become marginally elevated due to well bore liquid gradient. Further, because no gas is being injected down the side string tube the smallest leak will eventually cause the side string pressure to decline and falsely indicate a low liquid level as detected by pressure, therefore the termination point of the side string tube in the annulus must be very close to the desired level of liquid in the well bore to allow the liquids to intermittently fall below the termination point of the side string tube to thereby clear all liquid from the side string tube.
In a fourth embodiment of the invention, the same steps as the third embodiment are followed with the addition of the step of injecting a minuscule or relatively small volume of gas into the side string injection tube sufficient to displace the influx of liquid in the side string tube into the annulus while determining a differential pressure representative of the level of liquid in the well bore. In this method, any error resulting from the unknown side string tube liquid level is eliminated. The liquid level is thus more accurately determined for altering pump operation. In this method, the system is dynamic in that variations in the annulus and flow line pressure at surface will have no impact on the differential pressure between the annulus and the side string pressures. Furthermore, because the side string tube will have only a gas gradient within it, the differential pressure multiplied by the appropriate liquid gradient factor will determine an exact liquid level in the well bore. In this method, the operator will be able to choose very accurately, by virtue of pressure, the liquid level that he or she desires to carry in the well bore to best optimize the available rat hole to conserve energy necessary keep the productive formation dewatered and optimize production. Also in this embodiment, if the side string tube is terminated substantially below the highest desired liquid level in the well bore it is possible to allow the pump operations, if desirable, to be altered with a substantial variation of liquid level in the well bore as detected by pressure.
In yet another embodiment of the invention, any of the foregoing methods are followed and gas production is measured relative to the liquid level in the well bore, and the liquid level within the well bore is adjusted to maximize well production while simultaneously optimizing liquid level in the well bore. In many well bores, the lower section of the xe2x80x9cproductivexe2x80x9d formation above the rat hole does not actually contribute to production. This unnecessary reduction in liquid level causes inefficiency in the artificial lift system incorporating a pump in that more energy is required to lift a given volume of liquid to the surface of the ground. In this new interactive and dynamic method of control, production gas is measured at the well head to establish the current production volumes. The controller is programmed with conventional software to use time weighted production volume averages to determine the current well bore production based on actual measurements. The predetermined liquid level pressure (PSI) or differential pressure (DP) set point for the altering of pump operation is automatically adjusted upward so that the liquid level in the well bore rises as determined by any of the previous liquid level determination methods. As the liquid level rises, there will come a time when the gas production will decline within the specified time weighted average. At that point, the predetermined liquid level set point will be automatically reduced to alter the pump operation to decrease the level of liquid within the well bore. The well bore response in the form of increased volumetric production is then monitored. As the production increases within the specified time and volume parameters, the predetermined set point for the desired liquid level will continue to be automatically decreased until no more increase in production volume is detected within the specified time parameters. At that time, the predetermined liquid level set point will remain unchanged for a specified time period. At the end of the specified nonmanagement period, the liquid level management procedure described above will be repeated until the next dormant period. It is to be understood that the automated liquid level management method will be done with adjustments taking place over the course of many hours and possibly days, the end result being the maximum liquid level sustainable within a given well bore with minimal interference with production and a reduced need for artificial lift energy.
In yet another embodiment of the invention the liquid level detection method is used to alter pump operation for the timely use of energy. As is commonly known, peak electrical load hours require electric utility companies to invest large sums to meet the high demand caused by residential use for short periods of time in the morning and evening. Often oil and gas wells are drilled in great numbers in small geographical areas and the artificial lift systems powered by electricity use electrical energy from the same electrical power grid as the surrounding residences. If the power requirements for the oil or gas well artificial lift systems can be reduced or eliminated during the peak residential load hours a benefit will be realized to all the parties involved in electricity production and usage. In this method, the time is monitored relative to the peak load time established by the electrical utility company and pump operations are altered to balance the liquid removal requirements of the well bore with the need to reduce electrical energy consumption at appropriate and critical times. Obviously, the artificial lift system pump can be shut down to prevent the system from drawing power during peak hours but this shut down may cause the liquid level to rise in the well bore and reduce production down the gas production line. In this new and unique method the controller detects a time prior to peak load hours and adjusts the predetermined (PSI or DP) set point of liquid level in the well bore to a minimum value. Subsequently the pump operation is altered to reduce the liquid level in the well bore to substantially equal the predetermined value, then during the peak load hours the pump system can be shut down or pump speed reduced so as to eliminate or reduce the artificial lift system power draw from the electrical power grid. Further, because the liquid level has been reduced to a minimum level the empty rat hole in the well becomes storage for liquid entering the well bore to minimized the effect of liquid level on production volumes due to the fact that the liquid must first fill the rat hole before it can begin to cover the productive formation and interfere with production. In this method, while the pump will require increased amounts of energy to reduce the liquid level into the rat hole below the productive formation, the energy will be required at an off peak load time when the electrical grid has power to spare. In this embodiment the prudent and timely use of electrical energy will benefit all parties involved with the electrical grid while allowing the operator to minimize the impact on production.
The invention uses variations of a method of liquid level detection to provide improved control methods and apparatus for various types of gas or oil well artificial lift systems which enhance efficiency, improve production, are cost effective, environmentally friendly, contribute to operational predictability and safety, are diverse enough to accommodate various well bore configurations, and are able to automatically accommodate a dynamic well bore and support the prudent and timely use of energy resources.